Madison River at Three Forks, MT Artist – Monte Dolack Black Eagle dam – Missouri River – Montana 8-K on September 8, 2016 Investor Update September 2016

2 Forward Looking Statements Forward Looking Statements During the course of this presentation, there will be forward- looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” or “will.” The information in this presentation is based upon our current expectations as of the date hereof unless otherwise noted. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking statements. We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the Company’s most recent Form 10-K and 10-Q along with other public filings with the SEC. Company Information NorthWestern Corporation dba: NorthWestern Energy www.northwesternenergy.com Corporate Support Office 3010 West 69th Street Sioux Falls, SD 57106 (605) 978-2900 Montana Operational Support Office 11 East Park Butte, MT 59701 (406) 497-1000 SD/NE Operational Support Office 600 Market Street West Huron, SD 57350 (605) 353-7478 Director of Investor Relations Travis Meyer 605-978-2945 travis.meyer@northwestern.com

NWE: An Investment for the Long Term 3 • 100% Regulated electric & natural gas utility business • 100 year history of competitive customer rates, system reliability and customer satisfaction • Solid economic indicators in service territory • A diverse electric supply portfolio that is approximately 54% hydro and wind (combined MT & SD) • Customer service satisfaction scores above the JD Power survey average • Residential electric and natural gas rates below the national average • Solid system reliability (EEI 2nd quartile) • Low leaks per 100 miles of pipe (AGA 1st quartile) • Named a “Utility Customer Champion” by Cogent Reports (top trusted utility brand in the West region) • Consistent track record of earnings and dividend growth • Strong cash flows aided by net operating loss carry-forwards • Strong balance sheet and solid investment grade credit ratings • Recent hydro & wind transactions increase rate base & provide energy supply stability • Disciplined maintenance capital investment program • Reintegrating energy supply portfolio • Significant future investment in a comprehensive transmission, distribution, and substation infrastructure project to address asset lives, safety, capacity and grid modernization Pure Electric & Gas Utility Solid Utility Foundation Strong Earnings & Cash Flows Attractive Future Growth Prospects (NYSE Ethics) Best Practices Corporate Governance

About NorthWestern 4 Montana Operations Electric 359,000 customers 24,350 miles – transmission & distribution lines 851 MW nameplate owned power generation Natural Gas 191,500 customers 7,200 miles of transmission and distribution pipeline 18 Bcf of gas storage capacity Owns 66 Bcf of proven natural gas reserves South Dakota Operations Electric 62,800 customers 3,550 miles – transmission & distribution lines 440 MW nameplate owned power generation Natural Gas 45,700 customers 1,625 miles of transmission and distribution pipeline Nebraska Operations Natural Gas 42,000 customers 750 miles of distribution pipeline Beethoven

A Diversified Electric and Gas Utility 5 Gross Margin in 2015: Electric: $663M Natural Gas: $178M Gross Margin in 2015: Montana: $729M South Dakota: $102M Nebraska: $ 10M Average Customers in 2015: Residential: 579k Commercial: 111k Industrial: 7k NorthWestern’s ‘80/20’ rules: Approximately 80% Electric, 80% Residential and 80% Montana jurisdictional Above data reflects full year 2015 results. Jurisdiction and service type based upon gross margin contribution. See “Non-GAAP Financial Measures” slide in appendix for Gross Margin reconciliation.

NorthWestern Energy Profile 6 Financial and Company Statistics

Solid Economic Indicators 7 • Unemployment rates in all three of our states are meaningfully below National Average. • Customer growth rates historically exceed National Averages. Source: NorthWestern customer growth - 2008-2015 Forms 10-K Unemployment Rate: US Department of Labor via SNL Database 2/19/16 Electric: EEI Statistical Yearbook (published December 2014, table 7.2) Natural Gas: EIA.gov (Data table "Number of Natural Gas Consumers")

Strong Utility Foundation 8 Electric source: Edison Electric Institute Typical Bills and Average Rates Report, 1/1/16 Natural gas source: US EIA - Monthly residential supply and delivery rates as of 1/29/16  Customer service satisfaction scores in line or better than survey average (JD Powers)  Residential electric and natural gas rates below national average  Solid electric system reliability and low gas leaks per mile System Average Interruption Duration Index (SAIDI) NWE versus EEI System Reliability Quartiles

Track Record of Delivering Results 9 Notes: - ROE in 2011, 2012 , 2013, 2014 & 2015 on a Non-GAAP Adjusted basis, would be 10.5%, 9.8%, 9.6% ,9.4% & 9.9% respectively. - 2016 ROAE and 2016 Dividend payout ratio estimate based on midpoint of our updated guidance range of $3.20-$3.35. - Details regarding Non-GAAP Adjusted EPS can be found in the “Adjusted EPS Schedule” page of the appendix Return on Equity within 9.5% - 11.0% band over the last 5 years. Annual dividend increases since emergence in 2004. 5 Year (2011-2015) Avg. Return on Equity: 10.4% 5 Year (2011-2015) CAGR Dividend Growth: 7.5% Current Dividend Yield Approximately 3.5%

Investment for Our Customers’ Benefit 10 Over the past 7 years we have been reintegrating our Montana energy supply portfolio and making additional investments across our entire service territory to enhance system safety, reliability and capacity. We have made these enhancements with minimal impact to customers’ bills and lower than the US average bills, while delivering solid earnings growth for our investors. 2008-2015 CAGRs Estimated Rate Base: 16.9% GAAP Diluted EPS: 8.6% NWE typical electric bill: 1.5% NWE typical natural gas bill: (6.9%) US average electric bill: 2.2% US avg. natural gas bill *** (4.1%)

Total Shareholder Return 11 • 13 member peer group: ALE (Allete), AVA (Avista), BKH (Black Hills), EE (El Paso Electric), GXP (Great Plains), IDA (IDA Corp), MGEE (Madison Gas & Electric), OGE (OGE Energy), OTTR (Otter Tail Power), PNM (PNM Resources), POR (Portland Electric),, VVC (Vectren), WR (Westar)

While maintenance capex and total dividend payments have continued to grow since 2011 (16.6% and 14.8% CAGR respectively), Cash Flow from Operations has continued to outpace maintenance capex and averaged approximately $38 million of positive Free Cash Flow per year. With the addition of production tax credits from the Beethoven Wind project and continued flow-through tax benefits, we anticipate our effective tax rate rising into the low-twenties by 2020. Additionally, we expect NOLs to be available into 2020 to reduce cash taxes. Strong Cash Flows 12 (1) See “Non-GAAP Financial Measure” slide in appendix for Free Cash Flows reconciliation. Components of Free Cash Flow This expected tax rate and the expected availability of NOLs are subject to significant business, economic, regulatory and competitive uncertainties and contingencies, many of which are beyond the control of the Company and its management, and are based upon assumptions with respect to future decisions, which are subject to change. Actual results will vary and those variations may be material. For discussion of some of the important factors that could cause these variations, please consult the “Risk Factors” section of the preliminary prospectus. Nothing in this presentation should be regarded as a representation by any person that these objectives will be achieved and the Company undertakes no duty to update its objectives. (2) Net Operating Loss (NOL) Carryforward Balance (2) (1)

Balance Sheet Strength and Liquidity 13

2016 Earnings Guidance 14 NorthWestern reaffirms our full-year 2016 adjusted (Non-GAAP) guidance range of $3.20 - $3.35 per diluted share, based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories; • A consolidated income tax rate of approximately 6% to 10% of pre-tax income; and • Diluted average shares outstanding of approximately 48.6 million. Continued investment in our system to serve our customers and communities is expected to provide a targeted 7-10% total return to our investors through a combination of earnings growth and dividend yield. See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”. $2.60 - $2.75 $3.20-$3.35

The Hydro Facilities 15 Overview of Hydro Facilities Black Eagle Hydro Asset Integration • Montana Asset Optimization Study: As part of reintegrating the hydro facilities into our generation portfolio, we initiated an asset optimization study to maximize the value of our diverse generation portfolio. The study was recently completed and we are in the process of implementing new operating procedures that we anticipate will reduce both operating cost and market risk. Kerr Dam Conveyance / Hydro Compliance Filing • In accordance with the 1985 FERC relicensing, the facility was conveyed to the Confederated Salish and Kootenai Tribes (CSKT) on September 5, 2015. • As required by the MPSC order approving the hydro transaction, we filed a compliance filing in December 2015 to remove the Kerr project from the hydros cost of service and to adjust for actual revenue credits and property taxes. In January 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. We expect the MPSC to issue a final order during the second half of 2016. (1) As of June 2013. Despite the 2015 drought conditions in western Montana, the hydro assets generated at targeted capacity (5 year historical average). Talen Energy’s recently announced sale of 292 MW of hydro generation for $860 million (or $2,945 per KW) to Brookfield Renewables is significantly higher cost (49%) than the 439 MW of hydro generation we purchased for $870 million (or $1,982 per KW).

16 Highly Renewable Supply Portfolio Based upon 2015 delivered electric portfolio, approximately 54% of our total company owned and contracted supply is renewable or supports renewables. * Wind Owned delivered in 2015 includes a partial year of production from the Beethoven wind farm, which was acquired on September 25, 2015.

17 South Dakota Electric Operations The owned and rate-based cost of energy from the Beethoven wind project over the next 20 years is expected to be $44 million ($25 million net present value) less than the PPA alternative, thus benefitting our customers’ bills over the long-term. Beethoven Wind Project: In September 2015, we completed the purchase of the 80 MW Beethoven wind project, near Tripp, South Dakota for approximately $143 million from BayWa r.e. Wind LLC. The SDPUC granted approval of our request on placing the assets into rate base using a 3-year levelized rate calculation. We financed the project with $70 million in 25 year bonds at 4.26% and $57 million of equity, issuing 1.1 million shares at $51.81. South Dakota Rate Case: In October 2015, the SDPUC commissioners approved the settlement agreement we reached with the SDPUC staff and intervenors providing for an increase in base rates of approximately $20.2 million based on an overall rate of return of 7.24%. In addition, the settlement would allow us to collect approximately $9.0 million annually related to the Beethoven Wind Project. Source: BayWa r.e. Wind, LLC We anticipate net income to increase by approximately $13.6 million in 2016 as a result of full year impact of the rate adjustment and Beethoven acquisition. SD Electric Transmission: Effective October 1, 2015, we are a transmission owning member of Southwest Power Pool (SPP) for our South Dakota transmission operations. Marketing activities in SPP are handled for us by a third party provider acting as our agent. Upon entering SPP, we exited out of MAPP, which had been our transmission planning region.

Infrastructure Projects 18 • In Montana, our Distribution System Infrastructure Project (DSIP) and Transmission System Infrastructure Project (TSIP), both of which are currently in process, are to maintain a safe and reliable electric and natural gas distribution and transmission system. – The primary goals: – arrest and/or reverse the trend in aging infrastructure; – maintain/improve reliability and safety; – build capacity into the system; and – prepare our network for the adoption of new technologies. – Capital Investment – DSIP: approximately $360 million ($185 million spent through 2015) of capital investment into the multiyear project through 2020. – TSIP: approximately $188 million ($4 million spend through 2015) projected through 2020.

Capital Spending Forecast 19 Current estimated cumulative capital spending for 2016 through 2020 is $1.66 billion. This reflects a $187 million increase from the capital plan included in our 2015 10-K; approximately $122 million increase for internal combustion (IC) units in Montana and $65 million increase for a peaking facility in South Dakota. Spending on the added generation assets will be subject to the development of a plan for clear regulatory recovery. Additional information is available in our 2015 Montana and 2014 South Dakota Electric Resource Supply Plans. We anticipate funding the capital projects with a combination of cash flows, aided by NOLs anticipated to be available into 2020, and long-term debt. If other opportunities arise that are not in the above projections (natural gas reserves, hydro expansion, acquisitions, etc.), new equity funding may be necessary. * .0M

Montana 2015 Electric Supply Resource Plan 20 The resource initiatives and actions developed in 2015 Electricity Supply Resource Procurement Plan identify the critical future needs of our portfolio, including solutions to resolve our current negative planning reserve margin. The plan identifies how to co- optimize hydro, wind and thermal resources to best meet the anticipated large capacity needs with the least-cost, lowest-risk resources. A baseline life extension analysis indicates potential for 86 MW of hydro capacity additions. These additions are not included in the current plan but will continue to be evaluated for cost effectiveness. The Montana Public Service Commission doesn’t approve or reject plan, but will issue their own comments. Timeline yet to be determined. Spending on the generation assets will be subject to the development of a plan for clear regulatory recovery. Source: Company’s IRP or other publications

Montana 2015 Electric Supply Resource Plan 21 Spending on the generation assets will be subject to the development of a plan for clear regulatory recovery. * Assumes no retirements and no additions. ** Montana supply plan would add 689MW of capacity and require approximately $1.3 billion of investment through 2029. Current Capacity* Economically Optimal Portfolio**

Owned Owned Target Total Annual Need Natural Gas Reserves Opportunity 22 As we continue to add to our natural gas reserves portfolio, we anticipate a reduction in supply cost volatility for our customers. As a result of the October 2015 natural gas tracker order, we are required to make a filing prior to September 2016 to include our last two acquisitions (NFR and Devon) into rate base. First ~6 Bcf annual production acquired for ~$100M Remaining 6-7 Bcf annual production needed to meet target. Estimated cost of $50M to $100M We continue to pursue opportunities to secure low cost gas reserves for our customers. • Three acquisitions totaling approximately $100 million since September 2010: • 84.6 Bcf of natural gas reserves and associated gathering systems along with 82 miles of transmission. • Provides approximately 5.3 Bcf of annual production. • Target to own 50% of our 25 Bcf total annual need • Retail customers (20 Bcf) • DGGS & Basin Creek generation facilities (5 Bcf) • Current gas prices are very attractive for buyers but it is difficult to find sellers willing to transact at these low rates.

23 Regulatory Update Regulatory Item Current / Anticipated Action FERC / DGGS: April 2014 order regarding cost allocation at DGGS between retail and wholesale customers. FERC denied our request for rehearing and required us to make refunds. Refunds were made in June 2016. Also in June 2016, we filed a Petition for Judicial Review with the US Circuit Court of Appeals for the District of Columbia Circuit. Briefing schedule for this appeal has not been established. LRAM: MPSC October 2015 Order eliminating the lost revenue adjustment mechanism. Future rate filings will set rates to recover test-year costs and return. We are evaluating other revenue based regulatory mechanism (for example decoupling) that could be pursued to address these kinds of revenue losses and others, going forward. Natural Gas: MPSC October 2015 natural gas tracker order revising interim rates our last two gas production asset acquisitions and requiring a filing prior to October 2016 to place them into rate base. In conjunction with the filing required for our natural gas production assets in Montana, we expect to submit a natural gas distribution, transmission and storage rate filing based on a 2015 test year in September 2016. Rate Filings: Annual “First Look” process to evaluate need for rate filings in each of our jurisdictions based on a 2015 test year. Colstrip: In May 2016, the MPSC issued a final order disallowing recovery of replacement power costs included in the electric supply tracker related to a 2013 outage at Colstrip Unit 4. In August 2016, the MPSC denied our May 2016 motion for reconsideration. We anticipate filing for an appeal with the Montana District Court in September. Hydro Compliance Filing: In December 2015, we filed, with the MPSC, a hydro compliance filing to remove Kerr Project costs, adjust for actual revenue credits and increase property taxes to reflect actual amounts. In January 2016, the MPSC approved an interim adjustment and opened a separate contested docket requesting additional detail on the adjustment to rates. The MPSC identified additional issues and requested information. The MCC has filed testimony in this contested docket and we have responded to the testimony. A hearing is scheduled for September 12, 2016. We expect the MPSC to issue a final order during the fourth quarter of 2016.

24 Colstrip Unit 4 / Sierra Club Litigation Background • On March 6, 2013, the Sierra Club and the Montana Environmental Information Center (MEIC) (both are plaintiffs) filed suit in the United States District Court for the District of Montana (court) against the six individual Owners of the Colstrip Generating Station (Colstrip) • Colstrip consists of four coal fired generating units – units 1 & 2 are older than units 3 & 4. • NWE has a 30% joint interest in unit 4 and a risk sharing agreement with Talen Montana regarding the operation of units 3 & 4, which each party receives 15% of the combined output and respective operating and construction costs. • Original suit was for alleged violations of the Clean Air Act and the Montana State Implementation Plan. Current Results • On July 12, 2016 the parties lodged a consent decree with the court. • Decree provides the following • Dismisses all of the claims against all Colstrip units • Provides no shut down date for Units 3 & 4 • Provides that Units 1 & 2 must be shut down by July 1, 2022 (NWE has no ownership or role in Units 1 & 2 shut down) • Permits parties to petition the Court for costs and attorneys’ fees • Department of Justice filed with the Court stating they had no objection to the decree and the EPA did not object or file comment by the August 29th deadline. Up next • If the court approves the consent decree, all claims raised by plaintiffs against all four Colstrip units will be resolved • We intend to seek attorneys’ fees and cost from Sierra Club and the MEIC

Conclusion 25 Pure Electric and Gas Utility Solid Utility Foundation Strong Earnings and Cash Flows Attractive Future Growth Prospects Best Practices Corporate Governance

Appendix 26

Summary Financial Results (Second Quarter) 27

28 Gross Margin (Second Quarter) (dollars in millions) Three Months Ended June 30, 2016 2015 Variance Electric $ 176.2 $ 155.5 $ 20.7 13.3% Natural Gas 35.2 35.6 (0.4) (1.1%) Gross Margin $ 211.4 $ 191.1 $ 20.3 10.6% Increase in gross margin due to the following factors: $ 12.6 Lost revenue adjustment mechanism 10.0 South Dakota electric rate increase 6.1 Electric QF adjustment 0.9 Natural gas production 0.8 MPSC Disallowance 0.3 Electric retail volumes (1.3) Natural gas retail volumes (0.7) Electric transmission (1.4) Other $ 27.3 Change in Gross Margin Impacting Net Income $ (5.9) Hydro operations (Kerr conveyance) (2.7) Production tax credits recovered in trackers (0.6) Gas production gathering fees 2.2 Property taxes recovered in trackers $ (7.0) Change in Gross Margin Offset Within Net Income $ 20.3 Increase in Consolidated Gross Margin

Weather (Second Quarter) 29 The tables on the top represent the variances for the quarter from historical average and prior year. The 2nd quarter is primarily a heating degree period in our service territory – 2nd quarter typically has 1,200+ Heating Degree Days (HDD) versus less than 100 Cooling Degree Days (CDD). This year’s warm April primarily drove the difference in year-over-year variance. Heating Degree Days as Compared to Historical Average 3.5% Warmer 25.0% Warmer 64.7% Warmer 9.2% Warmer 1.9% Colder 18.7% Warmer 6.8% Warmer 38.3% Warmer 7.1% Warmer 18.1% Warmer 25.9% Warmer 10.3% Warmer 6.6% Warmer 18.6% Warmer 18.5% Warmer 22.9% Warmer 11.7% Warmer 19.7% Colder Graph depicts Mean Temperature Departure from Average Map source: National Centers for Environmental Information

Operating Expenses (Second Quarter) 30 Increase in operating expenses due mainly to the following factors: $10.9 million increase in OG&A $ 20.8 Insurance recovery, net (included in 2015) $ 1.6 Non-employee directors deferred compensation $ (5.6) Hydro operations (Kerr Conveyance) $ (1.3) Distribution System Infrastructure Project (DSIP) expenses $ (1.2) Bad debt expense $ (0.6) Gas production gathering expense $ (2.8) Other, including cost control measures $2.7 million increase in property and other taxes due primarily to plant additions and higher estimated property valuations in Montana, offset in part by a $0.3 million decrease from the conveyance of the Kerr project to the CSKT in September 2015. $4.2 million increase in depreciation and depletion expense primarily due to plant additions, including approximately $1.4 million of depreciation associated with the Beethoven wind project acquisition. (dollars in millions) Three Months Ended June 30, 2016 2015 Variance Operating, general & admin. $ 72.6 $ 61.7 $ 10.9 17.7% Property and other taxes 35.2 32.5 2.7 8.3% Depreciation and depletion 39.9 35.7 4.2 11.8% Operating Expenses $ 147.7 $ 129.9 $ 17.8 13.7%

Operating to Net Income (Second Quarter) 31 $3.5 million increase in interest expenses was primarily due to $2.9 million of interest associated with the MPSC disallowance, increased debt outstanding associated with the September 2015 Beethoven wind project acquisition and lower capitalization of allowance for funds used during construction (AFUDC). $0.2 million increase in other income due primarily to a $1.6 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which had a corresponding increase to operating, general and administrative expenses), offset by lower capitalization of AFUDC. $5.3 million decrease in income tax expense due primarily to higher flow-through repairs deductions, higher production tax credits associated with Beethoven wind project and lower pre-tax income. (dollars in millions) Three Months Ended June 30, 2016 2015 Variance Operating Income $ 63.7 $ 61.1 $ 2.6 4.3% Interest Expense (26.4) (22.9) (3.5) 15.3% Other Income 1.2 1.0 0.2 20.0% Income Before Taxes 38.5 39.2 (0.7) (1.8%) Income Tax (Expense)/Benefit (2.9) (8.2) 5.3 (64.6%) Net Income $ 35.6 $ 31.0 $ 4.6 14.8%

Balance Sheet 32

Cash Flow 33 Changes in working capital is largely attributed to the $30.8 million* refund to customers in June 2016 associated with the DGGS/FERC ruling. * $27.3 million of deferred revenues plus accrued interest of $3.5 million.

Income Tax Reconciliation (Second Quarter) 34 Even with approximately the same pre-tax income, our income taxes are considerably lower in second quarter 2016 versus the prior year largely due to higher flow through repairs deductions, higher production tax credits related to Beethoven wind farm and a benefit of state income tax, net of federal provisions.

Non-GAAP Adjusted Earnings (‘16 vs ’15) 35 The non-GAAP measures presented in the table above are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP.

Summary Financial Results (YTD thru Qtr 2) 36

Weather (YTD thru Qtr 2) 37 Average Temperature Ranks (last 122 years) Mean Temperature from Normal For the months January through June, the 2016 period was the 2nd warmest period in Montana, the 5th warmest in South Dakota and the 5th warmest in Nebraska over the last 122 years.

Non-GAAP Adjusted Earnings (‘16 vs ’15) 38 The non-GAAP measures presented in the table above are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP.

Non-GAAP Adjusted EPS 39 The non-GAAP measures presented in the table above are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP.

40 2015 to 2016 Reconciliation (2nd Quarter & YTD) (1) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5% (2) These items have offsets in operating expenses or income tax expenses that result in no impact to net income. Six Months Ended June 30 Pre-tax Net EPS Pre-tax Net EPS ($millions, except EPS) Income Income (1) Diluted Income Income (1) Diluted 2015 reported $39.2 $31.0 0.65$ $100.6 $82.4 1.74$ Gross Margin Lost revenue adjustment mechanism 12.6 7.7 0.16 10.6 6.5 0.13 South Dakota electric rate increase 10.0 6.2 0.13 18.6 11.4 0.24 Electric QF adjustment 6.1 3.8 0.08 6.1 3.8 0.08 Natural gas production 0.9 0.6 0.01 (0.7) (0.4) (0.01) MPSC Disallow ance 0.8 0.5 0.01 (9.5) (5.8) (0.12) Electric retail volumes 0.3 0.2 - (0.7) (0.4) (0.01) Natural gas retail volumes (1.3) (0.8) (0.02) (1.1) (0.7) (0.01) Electric transmission (0.7) (0.4) (0.01) (2.0) (1.2) (0.02) Other (1.4) (0.9) (0.02) (2.7) (1.7) (0.04) Subtotal: Gross Margin Items Impacting Net Income 27.3 16.9 0.34 18.6 11.5 0.24 Hydro operations - Kerr conveyance (5.9) (3.6) (0.07) (11.8) (7.3) (0.15) Production tax credits f low ed through trackers (2.7) (1.7) (0.03) (5.9) (3.6) (0.08) Gas production gathering fees (0.6) (0.4) (0.01) (1.0) (0.6) (0.01) Property taxes recovered in trackers 2.2 1.4 0.03 3.9 2.4 0.05 Subtotal: Gross Margin Items Not Impacting Net Income (2) (7.0) (4.3) (0.08) (14.8) (9.1) (0.19) Subtotal - Gross Margin 20.3 12.6 0.26 3.8 2.4 0.05 OG&A Expense Insurance recovery, net (20.8) (12.8) (0.26) (20.8) (12.8) (0.26) Non-employee director deferred compensation (1.6) (1.0) (0.02) (4.7) (2.9) (0.06) Hydro operations - Kerr conveyance 5.6 3.4 0.07 11.2 6.9 0.14 Distribution System Infrastructure Project (DSIP) expenses 1.3 0.8 0.02 1.6 1.0 0.02 Bad debt expense 1.2 0.7 0.01 2.2 1.4 0.03 Gas production gathering expense 0.6 0.4 0.01 1.0 0.6 0.01 Insurance reserves - - - (0.9) (0.6) (0.01) Other, including cost control measures implemented in 2016 2.8 1.7 0.03 0.8 0.5 0.01 Subtotal - OG&A Expense (10.9) (6.8) (0.14) (9.6) (5.9) (0.12) Other Depreciation and depletion expense (4.2) (2.6) (0.05) (8.2) (5.0) (0.10) Property and other taxes (2.7) (1.6) (0.03) (5.4) (3.3) (0.07) Interest expense (3.5) (2.1) (0.04) (4.8) (3.0) (0.06) Other income (includes offset to Non-employee compensation above) 0.2 0.1 - 2.6 1.6 0.03 Permanent and f low -through adjustments to income tax 5.0 0.10 4.4 0.09 Impact of higher share count - - (0.01) - - (0.04) Subtotal - Other (10.1) (1.2) (0.03) (15.8) (5.3) (0.15) Total EPS impact of above items (0.7) 4.6 0.08 (21.6) (8.8) (0.22) 2016 reported $38.5 $35.6 0.73$ $79.0 $73.6 1.52$ Three Months Ended June 30

Owned Energy Supply Transmission Distribution Electric (MW) MT SD Total 2015 Tx for Others MT SD Total Demand MT SD / NE Total Base load coal 222 210 432 Electric (GWh) 11,300 100 11,400 Daily MWs 750 187 937 Wind 40 80 120 Natural Gas (Bcf) 22.5 29.5 52.0 Peak MWs 1,790 306 2,096 Hydro 442 - 442 Annual GWhs 6,400 1,640 8,040 Other resources 150 150 300 Annual Bcf 18.5 9.5 28.0 854 440 1,294 System (miles) MT SD Total Electric 6,700 1,350 8,050 Customers MT SD / NE Total Natural Gas (Bcf) MT SD Total Natural gas 2,100 55 2,155 Electric 359,000 62,800 421,800 Proven reserves 65.9 - 65.9 8,800 1,405 10,205 Natural gas 191,500 87,700 279,200 Annual production 5.3 - 5.3 550,500 150,500 701,000 Storage 17.8 - 17.8 System (miles) MT SD / NE Total Electric 17,650 2,200 19,850 Natural gas 5,100 2,375 7,475 22,750 4,575 27,325 2015 System Statistics 41 Note: Statistics above are as of 12/31/2015 (1) Includes additional 3 MW for Ryan dam expansion (2) Nebraska is a natural gas only jurisdiction (2) (1)

Experienced & Engaged Board of Directors 42 Dr. E. Linn Draper Jr. • Chairman of the Board • Independent • Director since November 1, 2004 Stephan P. Adik • Committees: Audit (chair), Human Resources • Independent • Director since November 1, 2004 Dorothy M. Bradley • Committees: Human Resources, Governance and Innovation • Independent • Director since April 22, 2009 Robert C. Rowe • Committees: None • CEO and President • Director since August 13, 2008 Dana J. Dykhouse • Committees: Human Resources (chair), Audit • Independent • Director since January 30, 2009 Jan R. Horsfall • Committees: Audit, Governance and Innovation • Independent • Director since April 23, 2015 Julia L. Johnson • Committees: Governance and Innovation, Human Resources • Independent • Director since November 1, 2004

Strong Executive Team 43 Robert C. Rowe • President and Chief Executive Officer • Current position since 2008 Brian B. Bird • Vice President and Chief Financial Officer • Current position since 2003 Michael R. Cashell • Vice President - Transmission • Current Position since 2011 Patrick R. Corcoran • Vice President – Government and Regulatory Affairs • Current position since 2001 Heather H. Grahame • Vice President and General Counsel • Current position since 2010 John D. Hines • Vice President - Supply • Current Position since 2011 Crystal D. Lail • Vice President and Controller • Current position since 2015 Curtis T. Pohl • Vice President - Distribution • Current position since 2003 Bobbi L. Schroeppel • Vice President – Customer Care, Communications and Human Resources • Current Position since 2002

Our Commissioners 44 Name Party Began Serving Term Ends Kirk Bushman R Jan-13 Jan-17 Travis Kavulla R Jan-11 Jan-19 Roger Koopman R Jan-13 Jan-17 Brad Johnson (Chairman) R Jan-15 Jan-19 Bob Lake R Jan-13 Jan-17 Commissioners are elected in statewide elections from each of five districts. Chairperson is elected by fellow Commissioners. Commissioner term is 4 years, Chairperson term is 2 years. Montana Public Service Commission Name Party Began Serving Term Ends Kristie Fiegen R Aug-11 Jan-19 Gary Hanson R Jan-03 Jan-21 Chris Nelson (Chairman) R Jan-11 Jan-17 Commissioners are elected in statewide elections. Chairperson is elected by fellow Commissioners. Commissioner term is 6 years, Chairperson term is 1 year. South Dakota Public Utilities Commission Name Pa ty Began Serving Term Ends Cyrstal Rh ades D Jan-15 Jan-21 Rod Johnson R Jan-93 Jan-17 Frank Landis Jr. (Chairman) R Jan-89 Jan-19 Tim Schram R Jan-07 Jan-19 Gerald Vap R Aug-01 Jan-17 Commissioners are elected in statewide elections. Chairperson is elected by fellow Commissioners. Commissioner term is 6 years, Chairperson term is 1 year. Nebraska Public Service Commission

EPA’s 2030 carbon target for Montana NWE’s CO2 intensity* decreased by approximately 37% with the addition of the hydro facilities to our Montana generation portfolio. However EPA’s Clean Power Plan targets are statewide and not utility specific targets. * lbs CO2 per MWH produced CO2 Intensity* 37% 45 EOP = Emergency Operations Plan RPS = Renewable Portfolio Standard

46 EPA’s Clean Power Plan (CPP) The February 9th Supreme Court 5-4 vote to stay the EPA CPP rules • We will be working with state agencies and other stakeholders to evaluate the implications. • We hope the EPA takes this opportunity to address Montana’s serious concerns with the 47% statewide reduction required in the final rule. If the CPP rules were utility specific, NorthWestern would be in excellent shape…. but emission targets are established at a state level. • NorthWestern’s Montana electric supply portfolio has a low carbon emissions rate, lower than the final 2030 Montana rate mandated by EPA, with nearly 60 percent of the power delivered to NorthWestern’s customers coming from owned or contracted hydro or wind sources. • NorthWestern’s South Dakota electric supply portfolio delivers approximately 28% of its power from owned and contracted wind. Source: www.eenews.net/interactive/clean_power_plan Parallel paths forward • Montana and South Dakota, along with many other states, are participating in legal challenges to the rule. Montana’s 47% emission rate reduction requirement is the highest in the nation. • NorthWestern has filed an administrative Petition for Reconsideration with the EPA. If unsuccessful, we anticipate Montana will file a request for a 2-year extension to meet compliance deadlines. • Although we have filed for reconsideration, we are continuing to evaluate our path forward to comply with the CPP rule. The Montana governor has created a CPP advisory council whose purpose is to gather information and provide the Montana Department of Environmental Quality (MDEQ) recommendations on policies and actions necessary for compliance in Montana. With the Supreme Court decision to Stay the EPA CPP rules, the activities of the advisory council have been placed on hold. We have representation on the council.

DGGS Update – Denied Rehearing Request 47 Note: Please see Regulatory Matters footnote and Risk Factors section of our recent Form 10-K and Form 10-Q for additional disclosures.

Non-GAAP Financial Measures 48 The data presented in this presentation includes financial information prepared in accordance with GAAP, as well as other Non-GAAP financial measures such as Gross Margin (Revenues less Cost of Sales), Free Cash Flows (Cash flows from operations less maintenance capex and dividends) and Net Debt (Total debt less capital leases), that are considered “Non-GAAP financial measures.” Generally, a Non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of Gross Margin, Free Cash Flows and Net Debt is intended to supplement investors’ understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Net Debt is used by our company to determine whether we are properly levered to our Total Capitalization (Net Debt plus Equity). Our Gross Margin, Free Cash Flows and Net Debt measures may not be comparable to other companies’ similarly labeled measures. Furthermore, these measures are not intended to replace measures as determined in accordance with GAAP as an indicator of operating performance. (in thousands) 2011 2012 2013 2014 2015 Reported GAAP diluted EPS 2.53$ 2.66$ 2.46$ 2.99$ 3.17$ Non-GAAP Adjustments Weather (0.05) 0.14 (0.05) (0.02) 0.17 Rate adjustments - - - - - Insurance recoveries - - - - - Income tax adjustments (0.17) (0.06) - (0.47) - Transmission revenue - low hydro 0.05 - - - - Dispute with former employee 0.05 - - - - DGGS FERC ALJ initial decision (2011 portion) - 0.12 - - - Release of MPSC DGGS deferral - (0.05) - - - DSM Lost Revenue recovery - (0.05) (0.02) - - CELP arbitration decision - (0.79) - - - MSTI Impairment - 0.40 - - - Hydro Transaction costs - - 0.11 0.24 - Hydro operations (Nov. 18, 2014 - Dec. 31, 2014) - - - (0.14) - Hydro equity dilution - - - 0.08 - Remove ben f t of insurance settlement (0.27) QF liability adjustment 0.08 Adjusted Non-GAAP diluted EPS 2.41$ 2.37$ 2.50$ 2.68$ 3.15$ Use of Non-GAAP Financial Measures - Reconcile to Non-GAAP diluted EPS (in millions) Electric Gas Other Total Oper ting Revenues 944.4$ 269.9$ -$ 1,214.3$ Cost of Sales 281.3 91.6 - 372.9 Gro s Margin 663.2$ 178.3$ -$ 841.4$ (in millions) Montana South Dakota Nebraska Total Operating Revenues 985.3$ 195.6$ 33.4$ 1,214.3$ Cost of Sales 256.1 93.9 22.8 372.9 Gross Margin 729.2$ 101.7$ 10.5$ 841.4$ Use of Non-GAAP Financial Measures - Gross Margin for 2015 Use of Non-GAAP Financial Measures - Gross Margin for 2015

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